1. Technical Field of the Invention
The present Invention relates to method to stimulate the production of hydrocarbons from a subterranean formation. In particular, the present Invention discloses and claims methods to enhance removal of spent fracturing fluid from a fracture deliberately created in the formation, thereby increasing effective fracture length, and thereby increasing hydrocarbon production.
2. Introduction to the Technology
The present Invention relates generally to hydrocarbon (petroleum and natural gas) production from wells drilled in the earth. Obviously, it is desirable to maximize both the rate of flow and the overall capacity of hydrocarbon from the subsurface formation to the surface, where it can be recovered. One set of techniques to do this is referred to as stimulation techniques, and one such technique, "hydraulic fracturing," is the subject of the present Invention. The rate of flow, or "production" of hydrocarbon from a geologic formation is naturally dependent on numerous factors. One of these factors is the radius of the borehole; as the bore radius increases, the production rate increases, everything else being equal. Another, related to the first, is the flowpaths from the formation to the borehole available to the migrating hydrocarbon.
Drilling a hole in the subsurface is expensive--which limits the number of wells that can be economically drilled--and this expense only generally increases as the size of the hole increases. Additionally, a larger hole creates greater instability to the geologic formation, thus increasing the chances that the formation will shift around the wellbore and therefore damage the wellbore (and at worse collapse). So, while a larger borehole will, in theory, increase hydrocarbon production, it is impractical, and there is a significant downside. Yet, a fracture or large crack within the producing zone of the geologic formation, originating from and radiating out from the wellbore, can actually increase the "effective" (as opposed to "actual") wellbore radius, thus, the well behaves (in terms of production rate) as if the entire wellbore radius were much larger.
Fracturing (generally speaking, there are two types, acid fracturing and propped fracturing, the latter is of primary interest here) thus refers to methods used to stimulate the production of fluids resident in the subsurface, e.g., oil, natural gas, and brines. Hydraulic fracturing involves literally breaking or fracturing a portion of the surrounding strata, by injecting a specialized fluid into the wellbore directed at the face of the geologic formation at pressures sufficient to initiate and extend a fracture in the formation. More particularly, a fluid is injected through a wellbore; the fluid exits through holes (perforations in the well casing lining the borehole) and is directed against the face of the formation (sometimes wells are completed openhole where no casing and therefore no perforations exist so the fluid is injected through the wellbore and directly to the formation face) at a pressure and flow rate sufficient to overcome the minimum in-situ rock stress (also known as minimum principal stress) and to initiate and/or extend a fracture(s) into the formation. Actually, what is created by this process is not always a single fracture, but a fracture zone, i.e., a zone having multiple fractures, or cracks in the formation, through which hydrocarbon can flow to the wellbore.
In practice, fracturing a well is a highly complex operation performed with precise and exquisite orchestration of equipment, highly skilled engineers and technicians, and powerful integrated computers monitoring rates, pressures, volumes, etc. During a typical fracturing job, large quantities of materials often in excess of a quarter of a million gallons of fluid, will be pumped at high pressures exceeding the minimum principal stress down a well to a location often thousands of feet below the surface.
A typical fracture zone is shown in context, in FIG. 1. The actual wellbore--or hole in the earth into which pipe is placed through which the hydrocarbon flows up from the hydrocarbon-bearing formation to the surface--is shown at 10, and the entire fracture zone is shown at 20. The vertical extent of the hydrocarbon-producing zone is ideally (but not generally) coextensive with the fracture-zone height (by design). These two coextensive zones are shown bounded by 22 and 24. The fracture is usually created in the producing zone of interest (rather than another geologic zone) because holes or perforations, 26-36, are deliberately created in the well casing beforehand; thus the fracturing fluid flows down (vertically) the wellbore and exits through the perforations. Again, the reservoir does not necessarily represent a singular zone in the subterranean formation, but may, rather represent multiple zones of varying dimensions.
Thus, once the well has been drilled, fractures are often deliberately introduced in the formation, as a means of stimulating production, by increasing the effective wellbore radius. Clearly then, the longer the fracture, the greater the effective wellbore radius. More precisely, wells that have been hydraulically fractured exhibit both radial flow around the wellbore (conventional) and linear flow from the hydrocarbon-bearing formation to the fracture, and further linear flow along the fracture to the wellbore. Therefore, hydraulic fracturing is a common means to stimulate hydrocarbon production in low permeability formations. In addition, fracturing has also been used to stimulate production in high permeability formations. Obviously, if fracturing is desirable in a particular instance, then it is also desirable, generally speaking, to create as large (i.e., long) a fracture zone as possible--e.g., a larger fracture means an enlarged flowpath from the hydrocarbon migrating towards the wellbore and to the surface.
Yet many wells behave as though the fracture length were much shorter because the fracture is contaminated with fracturing fluid (i.e., more particularly, the fluid used to deliver the proppant as well as a fluid used to create the fracture, both of which shall be discussed below). The most difficult portion of the fluid to recover is that retained in the fracture tip--i.e. the distal-most portion of the fracture from the wellbore. Thus, the result of stagnant fracturing fluid in the fracture naturally diminishes the recovery of hydrocarbons. The reasons for this are both simple and complex. Most simply, the presence of fluid in the fracture acts as a barrier to the migration of hydrocarbon from the formation into the fracture. More precisely, the (aqueous-based fluid) saturates the pore spaces of the fracture face, preventing the migration of hydrocarbon into the same pore spaces, i.e., that fluid-saturated zone has low permeability to hydrocarbon.
Indeed, diminished effective fracture length caused by stagnant fluid retained in the fracture tip is perhaps the most significant variable limiting hydrocarbon production (both rate and capacity) from a given well. This is particularly true for low permeability gas reservoirs (approx. &lt;50 millidarcys). The significance of this stagnant fluid on well productivity is evidenced by the empirical observation well known to the skilled reservoir engineer that effective fracture lengths (the true fracture length minus the distal portion of the fracture saturated with fracturing fluid) are generally much less than the true hydraulically-induced fracture length. To achieve an increase in effective fracture length--so that it approaches the true fracture length-therefore involves removing stagnant fracturing fluid from the fracture.
The deliberate removal of fracturing fluid from the fracture is known as "clean-up," i.e., this term refers to recovering the fluid once the proppant has been delivered to the fracture. The current state-of-the-art method for fracture clean-up involves very simply, pumping or allowing the fluid to flow out of the fracture--thus the fracture fluid residing in the tip must traverse the entire length of the fracture (and up the wellbore) to be removed from the fracture. The present Application is directed to an improved method--and compositions to execute that method--for clean-up of the fracture.
Thus, the most difficult task related to fracture clean-up is to remove the stagnant fracture fluid retained in the fracture tip (i.e., farthest from the wellbore). Often, a portion of the fracture may be hydraulically isolated, or "cut-off" so that the hydrocarbon flowing from the formation into the fracture completely bypasses this tip region, as shown in FIG. 2. Ground level is shown at 5. The direction of hydrocarbon flow is shown at 38. Thus hydrocarbon flows-aided by the presence of the newly created fracture from the formation 40 into the fracture 42--traverses the fracture until it gets to wellbore 10 where it is recovered at the surface. A similar flowpath is shown at 44. These flowpaths can define two regions 46, a producing region, and 48, a non-producing region at the fracture tip that is isolated from the rest of the fracture since no hydrocarbon flows through this portion of the fracture, thus no pressure gradient exists. This phenomenon (in addition to others) ensures that the stagnant fracture fluid will remain in the fracture tip rather than being displaced by producing hydrocarbon, which can occur in the region shown at 46.
Generally speaking, creating a fracture in a hydrocarbon-bearing formation requires a complex suite of materials; four crucial components are usually required: a carrier fluid or proppant-carrying matrix, a viscosifier, a proppant, and a breaker. A fifth component is sometimes added, whose purpose is to control leak-off, or migration of the fluid into the fracture face. The first component is injected first, and actually creates/extends the fracture. Roughly, the purpose of these fluids is to first create/extend the fracture, then once it is opened sufficiently, to deliver proppant into the fracture, which keeps the fracture from closing once the pumping operation is completed. The carrier fluid is simply the means by which the proppant is carried into the formation. Numerous substances can act as a suitable carrier fluid, though they are generally aqueous-based solutions that have been either gelled or foamed or both. Thus, the carrier fluid is often prepared by blending a polymeric gelling agent with an aqueous solution (sometimes oil-based, sometimes a multi-phase fluid is desirable); often, the polymeric gelling agent is a solvatable polysaccharide, e.g., galactomannan gums, glycomannan gums, and cellulose derivatives. The purpose of the solvatable (or hydratable) polysaccharides is to thicken the aqueous solution so that solid particles known as "proppant" (discussed below) can be suspended in the solution for delivery into the fracture. Thus the polysaccharides function as viscosifiers, that is, they increase the viscosity of the aqueous solution by 10 to 100 times, or even more. During high temperature applications, a cross-linking agent is further added which further increases the viscosity of the solution. The borate ion has been used extensively as a cross-linking agent for hydrated guar gums and other galactomannans to form aqueous gels, e.g., U.S. Pat. No. 3,059,909. Other demonstrably suitable cross-linking agents include: titanium (U.S. Pat. No. 3,888,312), chromium, iron, aluminum and zirconium (U.S. Pat. No. 3,301,723). More recently, viscoelastic surfactants have been developed which obviates the need for thickening agents, and hence cross-linking agents, see, e.g., U.S. Pat. No. 5,551,516; U.S. Pat. No. 5,258,137; and U.S. Pat. No. 4,725,372, all assigned to Schlumberger.
The purpose of the proppant is to keep the newly fractured formation in the fractured state, i.e., from re-closing after the fracturing process is completed; thus, it is designed to keep the fracture open--in other words to provide a permeable path for the hydrocarbon to flow through the fracture and into the wellbore. More specifically, the proppant provides channels within the fracture through which the hydrocarbon can flow into the wellbore and therefore be withdrawn or "produced." Typical material from which the proppant is made includes sand (e.g. 20-40 mesh), bauxite, man-made intermediate strength materials and glass beads. The proppant can also be coated with resin to help prevent proppant flowback in certain applications. Thus, the purpose of the fracturing fluid generally is two-fold: (1) to create or extend an existing fracture through high-pressure introduction into the geologic formation of interest; and (2) to simultaneously deliver the proppant into the fracture void space so that the proppant can create a permanent channel through which the hydrocarbon can flow to the wellbore. Once this second step has been completed, it is desirable to remove the fracturing fluid from the fracture--its presence in the fracture is deleterious, since it plugs the fracture and therefore impedes the flow of hydrocarbon. This effect is naturally greater in high permeability formations, since the fluid can readily fill the (larger) void spaces. This contamination of the fracture by the fluid is referred to as decreasing the effective fracture length. And the process of removing the fluid from the fracture once the proppant has been delivered is referred to as "fracture clean-up." For this, the final component of the fracture fluid becomes relevant: the breaker. The purpose of the breaker is to lower the viscosity of the fluid so that it is more easily removed fracture. Nevertheless, no completely satisfactory method exists to recover the fluid, and therefore prevent it from reducing the effective fracture length. Again, fluid recovery after delivering the proppant to the fracture represents one of the major technological dilemmas in the hydrocarbon production field. The instant Invention is directed to methods for recovering the fracturing fluid once the fluid has successfully delivered the proppant to the fracture.
Diminished effective fracture length (EFL) caused by fracture fluid retention in the fracture is an empirically demonstrable problem that results in substantially reduced well yields. The EFL can be calculated by production decline and pressure transient analysis. The EFL values obtained this way can then be compared with the true fracture length obtained using standard geometry models.
Prior Art
Essentially, techniques for fracture clean-up, which again, refers to recovering the fracturing fluid (minus the proppant) from the fracture once it has delivered the proppant into the fracture, often involves reducing the fluid's viscosity as much as economically feasible--once the fluid has delivered the proppant into the fracture--so that it more readily flows back towards the wellbore. Again, the goal is to recover as much fluid as possible, since fluid left in the fracture reduces the effective fracture length. Among the most troublesome aspect of fluid recovery, or clean-up is recovering that portion of the fluid at the very tip of the fracture. Again, the fluid used to carry the proppant in to the matrix must have sufficient viscosity to entrain proppant particles. Yet once the proppant is placed in the fracture, it is desirable to get the fluid out, while leaving the proppant in place. Removing a viscous fluid from the fracture is difficult, therefore, fracturing fluids often contain additives to break the viscosity of the fracturing fluid once it has delivered the proppant into the fracture.
In summary, the genuine limiting factor in hydrocarbon production in low permeability reservoirs is the chronic inability to achieve suitable fracture clean-up. The goal in fracture clean-up is to achieve a suitable "effective" fracture length that approaches the true or actual fracture length. Thus, upon fracturing, fluid used to fracture the well remains in the fracture tip--this fluid prevents hydrocarbon production through that portion of the fracture. Therefore, numerous methods have arisen to address this problem. One potential solution is to simply create longer fractures (increase true fracture length which is bound to in turn increase effective fracture length). Longer fractures require greater expense to inject the fluid into the reservoir. At present, technology is near its cost-effective limit--that is, to create longer fractures would require new technology. Another possible solution is to obviate or at least diminish the need for fracture clean-up by pumping "cleaner" fluids--i.e., fluids with less polymer, and therefore which are less viscous, and therefore which are easier to flow back out of the fracture. This is a moderately acceptable solution; however low polymer fluids often means less proppant-carrying capacity, and therefore a smaller fracture. The overwhelming majority of candidate solutions lie within one of these two categories. The methods of the present Invention are directed to a third category: an improved method to remove fluid from the fracture tip. The present Invention is closely related to another application by the same inventors, Enhancing Fluid Removal From Fractures Deliberately Introduced into the Subsurface, U.S. patent application Ser. No. 09/087,286, assigned to Schlumberger.